There are two commonly used techniques to fracture in a completion method. FIG. 1 shows a borehole 10 that has a casing string 12 that is cemented 14 in the surrounding annulus 16. This is normally done through a cementing shoe (not shown) at the lower end of the casing string 12. In many cases if further drilling is contemplated, the shoe is milled out and further drilling progresses. After the string 12 is cemented and the cement 14 sets a perforating gun (not shown) is run in and fired to make perforations 18 that are then fractured with fluid delivered from the surface followed by installation and setting of packer or bridge plug 20 to isolate perforations 18. After that the process is repeated where the gun perforates followed by fracturing and followed by setting yet another packer or bridge plug above the recently made and fractured perforations. In sequence, perforation and packer/bridge plug pairs 22, 24; 26, 28; 30, 32; and 34 are put in place in the well 10 working from the bottom 36 toward the well surface 38.
A variation of this scheme is to eliminate the perforation by putting into the casing wall telescoping members that can be selectively extended through the cement before the cement sets to create passages into the formation and to bridge the cemented annulus. The use of extendable members to replace the perforation process is illustrated in U.S. Pat. No. 4,475,729. Once the members are extended, the annulus is cemented and the filtered passages are opened through the extending members so that in this particular case the well can be used in injection service. While the perforating is eliminated with the extendable members, the cost of a cementing job plus rig time can be very high and in some locations the logistical complications of the well site can add to the cost.
More recently, external packers that swell in well fluids or that otherwise can be set such as 40, 42, 44, 46, and 48 in FIG. 2 can be set on the exterior of the string 49 to isolate zones 50, 52, 54, and 56 where there is a valve, typically a sliding sleeve 58, 60, 62 and 64 in the respective zones. The string 49 is hung off the casing 66 and is capped at its lower end 67. Using a variety of known devices for shifting the sleeves, they can be opened in any desired order so that the annular spaces 68, 70, 72 and 74 can be isolated between two packers so that pressurized frac fluid can be delivered into the annular space and still direct pressure into the surrounding formation. This method of fracturing involves proper packer placement when making up the string and delays to allow the packers to swell to isolate the zones. There are also potential uncertainties as to whether all the packers have attained a seal so that the developed pressure in the string is reliably going to the intended zone with the pressure delivered into the string 49 at the surface. Some examples of swelling packer are U.S. Pat. Nos. 7,441,596; 7,392,841 and 7,387,158. There are also potential uncertainties as to the location of the fracture with the possibility of fractures initiating at the packers instead of the valve.